In the oil and gas exploration and production industries wellbores are drilled from surface to intercept subterranean formations or reservoirs. These wellbores may be used to produce fluids, such as oil and gas, from a subterranean reservoir to surface. Further, these wellbores may be used to inject a fluid, such as water or gas, into a subterranean region, for example for disposal, to assist in recovery of a further fluid to surface, and the like.
Wellbores are typically formed in stages, with a first section drilled with a drill bit mounted on the end of a drill string, and the drilled section then lined with casing which is cemented in place for sealing and support. Following this a drill string with a smaller diameter drill bit is run through the cased first section to advance the bore, with the further drilled section also lined with casing. This process is repeated until the bore intercepts the target formation or reservoir, with the reservoir section of the bore typically being lined with a reservoir liner, and cemented in place, and/or sealed via liner packers. As each new bore section is drilled with a drill bit of reducing diameter to permit passage of the drill string and casing/liner through the previous cased section, the diameter of the wellbore decreases with bore depth. In some cases the reservoir liner may define a diameter of, for example, 178 mm (7″).
During each drilling stage a drilling fluid, known as drilling mud, is circulated through the bore. This drilling mud has multiple functions, such as to lubricate and cool the drill bit, to carry drill cuttings back to surface, and to control the hydrostatic pressure within the bore and establish a desired balance between the bore pressure and surrounding reservoir pressure to minimise the risk of inflow from the formation during this bore forming stage.
Once the reservoir section is lined, this may be perforated at various locations along its length to establish fluid communication between the reservoir and the wellbore. Where the wellbore is required for producing reservoir fluids to surface a production completion is installed, which includes a production tubing string with multiple in-flow ports along its surface to facilitate entry of reservoir fluids to be communicated to surface.
In many instances efficient production rates can only be achieved if the reservoir is first stimulated. Many stimulating techniques are known, such as fracturing and acid stimulation, which usually function to effectively increase the porosity of the reservoir, especially in the near wellbore region which may have suffered damage during drilling. The present applicant has developed a technique known as the Perforate, Stimulate and Isolate (PSI) completion system, in which individual sealed zones within the perforated liner are established by use of a number of packers mounted on the production string. The production string includes sliding sleeves which are opened to permit outflow of a stimulating fluid, such as an acid, fracturing fluid and the like, into each isolated zone and ultimately into the reservoir via the liner perforations. These sliding sleeves are typically operated by coiled tubing extended from surface, and as such the total length of this type of completion is restricted to the reach of the coiled tubing.
To maximise the interface area between the wellbore and the reservoir, and therefore maximise recovery rates, it is common practice to form extended lateral or horizontal wellbore sections. For example, such lateral wellbores are extensively used in the Dan/Halfdan oil accumulation, offshore Denmark. However, the extent of such lateral wells may be limited by the desired or required completion techniques. For example, the PSI completion system, as noted above, is limited by the maximum reach of coiled tubing. Also, in some circumstances, although a bore may be drilled to a significant depth it may not be possible to line or case the bottom part of such a bore with a conventional cemented reservoir liner, and subsequently perforate this to establish communication with the reservoir.
It has been proposed in the art to leave extended reach sections of a bore unlined or open, and permit communication of reservoir fluids directly through the bore/reservoir interface region. However, it is extremely difficult to stimulate such open hole sections, for example due to the complexity and often the inability to run and install completion equipment at such depths. Also, as noted above, the process of drilling the bore often has a detrimental effect on the bore/reservoir interface region, causing damage in the near-wellbore region, resulting in a reduction in porosity and permeability and thus restricting inflow of reservoir fluids. This damage or reduction in porosity and permeability is often termed the wellbore skin, and must be addressed to ensure efficient and maximum production rates are achieved.
For example, the drilling fluid or mud used during the drilling process may form a layer or coating on the surface of the bore, called mud or filter cake, which presents a restriction to inflow from the reservoir. This mud cake must be removed to improve the rate of inflow from the reservoir, and again difficulties exist due to the depths involved.
The present applicant has developed a technique for use in stimulating extended reach reservoir sections, which is disclosed in EP 1 184 537, US 2009/0294122 and in SPE paper 78318 entitled “Controlled Acid Jet (CAJ) Technique for Effective Single Operation Stimulation of 14,000+ft Long Reservoir Sections”. The disclosure of each of these documents is incorporated herein by reference. This technique involves running a liner, called a Controlled Acid Jet (CAJ) liner, into a drilled bore which extends beyond an existing lined bore section, wherein the CAJ liner is sealed against the upper liner. The CAJ liner includes a number of pre-drilled holes extending through its wall, which permit an acid pumped from surface to exit the CAJ liner and into the annulus between the liner and the bore wall. This acid functions to break down the mud cake and then flow into the reservoir to stimulate the reservoir.
In this known technique, however, the fluid, such as drilling mud, resident in the bore prior to running in the CAJ liner cannot be circulated out, and is effectively also displaced into the formation with the acid. This may require increased volumes of acid to be used, and may result in a degree of dilution of the acid, making it less effective. Further, the inability to circulate the resident fluid from the annulus may result in this fluid eventually being produced to surface with the formation fluids, and thus necessitating its eventual separation from the formation and other fluids.
Blow Out Preventors (BOP) are commonly located at a wellhead of an oil or gas well to control or seal the well in the event of a sudden pressure increase or “kick” in the wellbore such as may occur during drilling operations as a result of a sudden in-flow of fluid from a formation surrounding the well. One known type of BOP may comprise one or more pairs of rams for sealing the well. For example, known types of BOPs may comprise one or more pairs of pipe rams, one or more pairs of blind rams and/or one or more pairs of shear rams. Pipe rams may be employed to seal against a tubular string which extends through the BOP so as to seal an annulus defined between an outer surface of the tubular string and a sidewall of the wellbore. Blind rams may be used to seal the well when there is no tubular string extending through the BOP. Shear rams are generally capable of shearing a tubular string such as a drill string or a running string that extends through the BOP. Shear rams are generally only employed as a last resort to control the well in an emergency when it is not possible or it is not appropriate to seal the well using pipe rams and/or blind rams. Shearing a tubular string using shear rams is undesirable for several reasons. For example, it can be difficult and time-consuming to retrieve the lower part of the tubular string after shearing. The shearing process is destructive and it is necessary to replace the tubular string after shearing. Furthermore, the shear rams of the BOP may also need to be inspected and/or replaced after shearing.
CAJ liners are commonly deployed through a BOP. However, in the event of a pressure kick in the wellbore, it is not possible to seal the well using pipe rams because fluid would be able to the bypass the pipe rams via the ports of the CAJ liner. Accordingly, it is known to drop the CAJ liner through the BOP to facilitate closing of BOP blind rams for control of the well. In practice, however, this known technique may only be reliable for CAJ liners of a length which is limited to a length of the existing lined section of the wellbore. This is because dropping the CAJ liner through the BOP may have the result that the CAJ liner will fall relative to the existing lined section of the wellbore and stick or jam on a sidewall of the open hole section located below a downhole end of the lined section of the wellbore. If the CAJ liner length exceeds the length of the existing lined section of the wellbore, an upper end of the CAJ liner may then continue to protrude upwardly from the BOP thus preventing the use of blind rams or pipe rams for sealing the well. Under such circumstances, it may be necessary to employ BOP shear rams to shear the CAJ liner for control of the well. It is, however, normally unacceptable well control practice to rely solely on shear rams as means of securing the well. It is also undesirable because it may be difficult and time-consuming to retrieve the lower part of the CAJ liner after shearing, it may be necessary to replace the CAJ liner after shearing, and because the shear rams of the BOP may need to be inspected and/or replaced after shearing the CAJ liner.